US20140192621A1 - Apparatus and method for communication between downhole components - Google Patents

Abstract

A method of synchronization between downhole components includes: generating a dual tone synchronization signal by a signal generator in a first downhole component disposed in a borehole in an earth formation, the dual tone signal including a first constituent periodic signal having a first frequency f₁and a second constituent periodic signal having a second frequency f₂that is different from the first frequency; transmitting the synchronization signal to a second downhole component disposed in the borehole; receiving the synchronization signal by a signal processor in the second downhole component, calculating a phase difference between the first constituent signal and the second constituent signal, and calculating a transmission delay based on the phase difference; and synchronizing operation of the first and second downhole components based on the delay.

Description

BACKGROUND
• Various techniques are used to measure formation properties, such as transient electromagnetic (EM) measurement techniques. Transient EM methods such as transient logging while drilling (LWD), especially using “look-ahead” capability, have been shown to have great use in geologic formation evaluation and measurement. Transient EM techniques involve disposing a tool including at least one transmitter and receiver, and transmitting transient pulses of current into a formation. The induced electromagnetic field and decay responses are measured. For proper operation of the transient EM tool, the transmitter and receiver must be well synchronized, i.e., the receiver data acquisition should start at the same instant of the transmit trigger, to within an error of, e.g., a few hundred nanoseconds.
• It has been conventional to the industry to assemble a LWD or wireline tool string from individual modules (also referred to as subassemblies or “subs”) which perform various functions and carry out various measurements while the string has been lowered in the borehole. However, even though these subs are mechanically attached to each other and share common power, the string communication abilities remains limited. For instance, in operations such as LWD or production logging where a single conductor carries power and telemetry signals, the telemetry uses a unique master controller which respectively sends commands to a particular sub and/or accepts a reply. This type of data transfer in general denies the modules the ability to communicate directly with each other which in turn may severely limit some applications, e.g., multicomponent transient EM (TEM) and multicomponent induction applications.
SUMMARY
• A method of synchronization between downhole components includes: generating a dual tone synchronization signal by a signal generator in a first downhole component disposed in a borehole in an earth formation, the dual tone signal including a first constituent periodic signal having a first frequency f₁and a second constituent periodic signal having a second frequency f₂that is different from the first frequency; transmitting the synchronization signal to a second downhole component disposed in the borehole; receiving the synchronization signal by a signal processor in the second downhole component, calculating a phase difference between the first constituent signal and the second constituent signal, and calculating a transmission delay based on the phase difference; and synchronizing operation of the first and second downhole components based on the delay.
• An apparatus for communicating between downhole components includes: an interface coupled to a first downhole component, the interface configured to communicatively couple the first downhole component to a transmission line and transmit signals to a second downhole component over the transmission line, the interface including a current loop transmitter configured to convert voltage signals from the first downhole component to current signals and transmit the current signals on a current loop formed by the transmission line.
BRIEF DESCRIPTION OF THE DRAWINGS
• The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:
• FIG. 1 depicts an embodiment of a drilling, formation evaluation and/or production system;
• FIG. 2 depicts an embodiment of a portion of a borehole string including transient electromagnetic (TEM) transmitter and receiver subassemblies;
• FIG. 3 depicts an embodiment of a communication assembly;
• FIG. 4 depicts an embodiment of an interface of the communication assembly ofFIG. 3;
• FIG. 5 depicts an embodiment of a one-way dual tone synchronization signal;
• FIG. 6 is a state diagram showing the operation of a TEM transmitter subassembly during a synchronization and measurement operation;
• FIG. 7 is a state diagram showing the operation of a TEM receiver subassembly during a synchronization and measurement operation;
• FIG. 8 depicts an embodiment of a subassembly current loop communication configuration;
• FIG. 9 depicts an embodiment of the configuration ofFIG. 8 in a half-duplex arrangement; and
• FIG. 10 depicts an embodiment of the configuration ofFIG. 8 in a full-duplex arrangement.
DETAILED DESCRIPTION
• Apparatuses and methods are provided for performing downhole operations such as electromagnetic (EM) measurement operations, including logging-while-drilling (LWD) and/or wireline operations. The apparatuses and methods also provide for direct communication between downhole components over a power and/or communication line extending along a borehole string. An exemplary method is provided for performing transient EM (TEM) logging operations, and for direct communication between downhole components. An exemplary apparatus and method provides for direct communication between subassemblies for, e.g., synchronization between a master subassembly (e.g., an EM transmitter) and another subassembly (e.g., an EM receiver). In one embodiment, synchronization is performed via a dual frequency one-way time delay measurement method. An embodiment of a communication apparatus or assembly includes interfaces for implementing a data channel in a bus or other transmission line for sending high-speed data from the master subassembly to affected subassemblies without interfering with other telemetry and power signals (e.g., between downhole components and surface units) already present on the transmission line.
• Referring toFIG. 1, an exemplary embodiment of a well drilling, logging and/orproduction system10 includes aborehole string12 that is shown disposed in a wellbore orborehole14 that penetrates at least oneearth formation16 during a drilling or other downhole operation. Asurface structure18 includes various components such as a wellhead, derrick and/or rotary table for deploying and supporting the borehole string. In one embodiment, theborehole string12 is a drillstring including one or more drill pipe sections that extend downward into theborehole14, and is connected to adrilling assembly20. In one embodiment,system10 includes any number of downhole tools orother components24 for various processes including communication, measurement, drilling, geosteering, and formation evaluation (FE) for measuring versus depth and/or time one or more physical quantities in or around a borehole. Thetool24 may be included in or embodied as a bottomhole assembly (BHA)22, drillstring component or other suitable carrier. In the embodiment shown inFIG. 1, various tools and other components are configured as subassemblies or “subs” that are connected together and/or with other portions of thestring12.
• TheBHA22 and/or other portions of theborehole string12 include sensor devices configured to measure various parameters of the formation and/or borehole. In one embodiment, the sensor devices include one or more transmitters and receivers configured to transmit and receive electromagnetic signals for measurement of formation properties such as composition, resistivity and permeability. An exemplary measurement technique is a transient EM (TEM) technique.
• In one embodiment, thetool24,BHA22 and/or sensor devices include and/or are configured to communicate with a processor to receive, measure and/or estimate directional and other characteristics of the downhole components, borehole and/or the formation. For example, thetool24 is equipped with transmission equipment including a power and/ordata transmission line30 to communicate with a processor such as adownhole processor26 or asurface processing unit28. Such transmission equipment may take any desired form, and different transmission media and connections may be used. Examples of connections include wired, fiber optic, acoustic, wireless connections and mud pulse telemetry.
• FIG. 2 illustrates an embodiment of thedownhole tool24. In this embodiment, thetool24 includes one or more sections or assemblies for performing electromagnetic (EM) measurements. For example, thetool24 is configured as a transient EM (TEM) tool, which may be configured as a logging while drilling (LWD) tool. The TEM tool includes a transmitter that periodically produces fast magnetic dipole reversals that induce eddy currents in the surrounding earth formation. These eddy currents induce voltage in one or more receiver sensors. The received voltage signals are processed to produce a model of the geometrical structure of the resistivity surrounding the borehole. Such models may be used to estimate characteristics of the formation or may be used for steering a drill bit to locate the borehole for maximum hydrocarbon production.
• In one embodiment, thedownhole tool24 includes separate subassemblies or “subs” that incorporate the transmitter and receiver(s). For example, atransmitter sub32 houses an EM transmitter34 (including, e.g., a transmitter antenna or coil) and associated electronics, which is configured to transmit EM pulses into the formation and is connected to thetransmission line30. Thetransmitter sub32 is connected to areceiver sub36 that houses one ormore EM receivers38 and40 (e.g., receiver coils) and associated electronics, which is configured to receive EM signals from the formation and is also connected to thetransmission line30. Thesubs32 and36 are connected together via connection mechanism42 (e.g. a pin-box connector). An electric source, which may be disposed downhole or at a surface location, is configured to apply electric current to thetransmitter34 through, e.g., thetransmission line30. Although thesubs32 and36 are shown in direct connection, they are not so limited, as other subs, pipe sections or tools may be connected between them.
• Although thetool24,EM transmitter34 andEM receivers38 and40 are described as being incorporated in downhole subs, they may be incorporated into any suitable downhole component, module or other carrier. A “carrier” as described herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. Exemplary non-limiting carriers include drill strings of the coiled tubing type, of the jointed pipe type and any combination or portion thereof. Other carrier examples include casing pipes, wirelines, wireline sondes, slickline sondes, drop shots, downhole subs, bottom-hole assemblies, and drill strings.
• In one embodiment, the transmitter and the receivers are disposed axially relative to one another. An “axial” location refers to a location along the Z axis that extends along a length of thetool24 and/orborehole14. Thereceiver40 is positioned at a selected axial distance L₁from thetransmitter34, and thereceiver38 is positioned at a shorter axial distance L₂from the transmitter.
• Referring toFIGS. 3 and 4, in one embodiment, thetool24 includes a communication or telemetry system orapparatus44 for communication between downhole components or subassemblies that utilizes the data and/orpower transmission line30. In the embodiment shown inFIG. 3, thetransmission line30 is a single conductor bus capable of transmitting power and communications. For example, thetransmission line30 is configured to transmit DC voltage and communications. An exemplary communication scheme incorporates a communications signal (e.g., using frequency shift keying modulation) having a 250 kHz carrier. Digital transmission can be accomplished at, e.g., a 9600 baud rate. Thetransmission line30, in this example, powers separate subassemblies on thestring12 by thetransmission line30 with return current through thestring12.
• TheEM transmitter sub32 and theEM receiver sub34 each include a communication assembly that connects the EM transmitter/receiver electronics to thetransmission line30. For example, theEM transmitter sub32 includes a synchronizationsignal generation assembly46 and theEM receiver sub34 includes a synchronizationsignal processing assembly48. Aninterface50 is included in each communication assembly that adds a communication channel to thetransmission line30.
• In one embodiment, eachinterface50 is a relatively narrow-band high frequency interface (e.g., around 4 MHz) added between the sub electronics and thetransmission line30. In one embodiment, shown inFIG. 4, theinterface50 is designed with a trap or high frequency band-pass filter52 to block signals having frequencies corresponding to carrier frequencies used in the transmission line's main communication channel (e.g., around 250 kHz), so that the channel does not interfere with other communications transmitted over thetransmission line30.
• In one embodiment, one of the subassemblies (e.g., the EM transmitter sub32) is configured as a master subassembly and has the capability to inject signals into theinterface50 to be broadcast to selected subassemblies or individual receivers (e.g., theEM receiver sub36 or one of theEM receivers38,40) over thetransmission line30. The injected narrow-band (e.g., 4 MHz) signals can be either synchronization signals for time synchronization purposes or data transmission signals over the injected carrier.
• For example, thetransmitter communication assembly46 includes amodem54 for modulating data signals56 from the transmitter, and a synchronization (sync)signal generator58 for transmitting synchronization signals. The receiver sub36 (or eachreceiver38 and40) includes amodem54 for demodulating data signals and async processor60 for receiving and processing synchronization signals.
• In one embodiment, for time synchronization between transmitters and receivers, thesync generator58 includes a dual tone signal generator capable of generating tones with fixed phase difference. The sync generator outputs a signal generated by two constituent signals having a fixed initial phase relationship. Each constituent signal has a different frequency or tone. In one embodiment, the constituent signals each have a frequency that falls within the frequency band of the channel added to thetransmission line30 by theinterface50.
• In order to receive the dual tone signal, thesync processor60 includes a phase sensitive receiver connected to the added channel of thetransmission line30. Thesync processor60 is configured to measure or calculate the difference in phase of the two tones transmitted by the master subassembly. In one example, thesignal processing assembly48 includes a digitizer followed by a Fourier transform processing routine that measures phase difference of the received tones.
• It is noted that the subassemblies are not limited to the embodiments and configurations described herein. For example, theEM receiver sub36, described as a synchronization signal receiver inFIG. 3, may be configured as a communication signal transmitter and/or master for communicating the with other subassemblies and/or theEM transmitter sub32. Likewise, theEM transmitter sub32 may be configured as a communication signal receiver. In other embodiments, thesubassemblies32,36 and/or other subassemblies may be configured to both transmit and receive communication signals over thecommunication line30. As described herein, “communication signals” refer to signals transmitted directly between downhole components over thetransmission line30, and can be distinguished from power and/or telemetry signals transmitted between downhole components and a surface and/or control unit.
• FIGS. 5-7 illustrate a method for synchronizing components of a borehole string or carrier using signals transmitted over a downhole transmission line, using a one-way synchronization signal. The method includes one or more stages described herein. The method may be performed by one or more processors or other devices capable of receiving and processing measurement data. In one embodiment, the method includes the execution of all of stages in the order described. However, certain stages may be omitted, stages may be added, or the order of the stages changed.
• In the first stage, theborehole string12, including downhole components such as theEM transmitter sub32 and theEM receiver sub36, is lowered in the borehole. Thestring12 may be lowered, for example, during a drilling operation, LWD operation or via a wireline.
• In the second stage, the master component (e.g., the EM transmitter sub32), transmits a synchronization signal to another downhole component (e.g., the EM receiver sub36). In one embodiment, the master component transmits a trigger signal to the downhole component in addition to the synchronization signal. The trigger signal is a signal indicating a time value associated with the master component. For example, the trigger signal indicates the time value at which theEM transmitter sub32 commences transmission of transient EM signals into the formation.
• An exemplary synchronization signal is shown inFIG. 5, which illustrates adual tone signal62 including frequencies f₁and f₂that is sent from theEM transmitter sub32 that includes two signals having different frequencies and having a fixed phase relationship. As shown inFIG. 5, the dual tone signal forms a two-tone envelope.Signal64 is the dual tone signal as received by theEM receiver sub36 and is used to calculate a transmission delay based on the phase difference, φ(f₂)−φ(f₁), between the two frequencies. The trigger signal indicates the time as measured by the transmitter in which the transmitter fired an EM pulse into the formation. For example, the trigger signal indicates that the EM pulse was fired by the transmitter at a time corresponding to a zero-crossing point of a selected cycle of the dual tone envelope, although any temporal point on the dual tone signal may be used to correspond to the trigger time.
• FIG. 6 is a state diagram70 showing an example of the EM transmitter sub operation during the second stage. Atstate71, thesync generator58 is enabled to generate a dual tone signal with zero phase between tones. After a selected number (N1) of dual tone cycles (state72), thetransient EM transmitter34 is triggered to emit a series of EM pulses into the formation (state73). The dual tone signal is transmitted to theEM receiver sub36 along with a trigger signal indicating the trigger point (e.g., zero crossing at N1 cycle). Instate74, theEM transmitter sub32 collects data indicating the axis and polarity of each dipole reversal for each pulse. This polarity and axis information is also transmitted to the receiver subassembly over thetransmission line30, using the modem54 (state75 and76).
• In the third stage, the other downhole component (e.g., EM receiver sub36) receives the trigger signal and the synchronization signal. The time of the trigger is noted, i.e., its position in the synchronization signal, and recording of TEM voltage signals from the formation by theEM receiver38 or40 is commenced. In one embodiment, theEM receiver sub36 includes a circular buffer, and the trigger causes theEM receiver sub36 to store data from the buffer at the trigger time and record subsequent data as needed. TheEM receiver sub36 also analyzes the synchronization to calculate the time delay τ that corresponds to the amount of time required to transmit the trigger to theEM receiver sub36. This delay is used to adjust the trigger time for the receiver data so that the received TEM data is synchronized with the transmitter.
• In one embodiment, the receiver calculates the delay τ based on the phase difference between the two tones or frequencies f₁and f₂. For example, a fast Fourier transform (FFT) is used to calculate the phase difference φ(f₂)−φ(f₁). The delay may then be calculated based on:
• $\tau =\frac{\phi \left(f_2\right)-\phi \left(f_1\right)}{2\pi \left(f_2-f_1\right)}.$
• FIG. 7 is a state diagram80 showing an example of the receiver subassembly operation during the third stage. Instate81, theEM receiver sub36 is idle and awaiting a synchronization signal. TheEM receiver sub36 may also receive a trigger signal indicating the trigger point. Upon receiving a dual tone signal, theEM receiver sub36 waits for N1 cycles, notes the end time of the trigger and commences FFT processing to calculate the delay (state82). At this point, theEM receiver sub36 commences recording voltage signals, and may also store data recorded in a buffer. Instate83, theEM receiver sub36 enables themodem54 and awaits receipt of data from theEM transmitter sub32 indicating, e.g., dipole shape, polarity and sensor axis for each pulse. After all TEM voltage signal data has been acquired and information data received, the voltage signal data is matched to the delay and the voltage data is processed (or transmitted to a remote processor) to analyze the formation, e.g., by generating or updating a formation model.
• In the fourth stage, a measurement operation is performed using the transmitter and receiver subassemblies. The measured voltage signals may be transformed, e.g., using a Fourier transform. The measured or transformed signals may be inverted or otherwise analyzed to estimate characteristics of the formation and/or borehole for the purpose of, e.g., formation evaluation and geosteering. For example, measured or transformed frequency domain TEM signals are inverted to provide estimations of formation properties, such as resistivities and distances to interfaces or boundaries in the formation.
• FIGS. 8-10 illustrate embodiments of aninterface50 that allows for electrical and communicative coupling between downhole tools or other components (e.g., theEM transmitter sub32 and the EM receiver sub36) and a communication line such as thebus30. In many configurations, borehole strings such as LWD and wireline tool string include individual subs, modules or other components that are mechanically attached to each other and receive power from the communication line such as thetransmission line30, which may include one or more electrical conductors and/or other components such as optical fibers. The communication line allows the subs to be in communication with a master controller (e.g., the surface processing unit28) for sending data, receiving commands from the controller and sending replies. Theinterface50 allows individual subs to directly communicate with one another, in contrast to forcing the subs to communicate via the master controller. The interface allows communication modules installed in different and separate subs in the downhole string to communicate directly with each other utilizing an existing single conductor bus or other telemetry configuration without interfering with pre-existing telemetry and power signals already present on the bus.
• In one embodiment, theEM transmitter sub32 and theEM receiver sub36 each include a current loop transmitter and/or current loop receiver that form part of a current loop communication system for direct communication between theEM transmitter sub32 and theEM receiver sub36 over the communication line. The current loop transmitter is configured to receive a voltage signal (e.g., data, commands or other communications) from the EM transmitter or receiver, convert the sensor signal to a current and inject the current into a current loop formed by the communication line. The current signal generated by the current loop transmitter is tuned to a frequency that is different than the communication line's pre-existing carrier frequency or frequencies.
• An example of a current loop communication configuration is shown in the circuit diagram ofFIG. 8. In this example, downhole components such as theEM transmitter sub32 and theEM receiver sub36 each include acurrent loop transceiver90 connected to the sub electronics and having the capability to both transmit and receive current signals. Each transceiver has a termination network L1, C4, X1, C1 and R1, which is designed to present a low impedance to thetransmission line30 at the carrier frequency (e.g. 4 MHz), but presents a high impedance to the line at all other frequencies (e.g. the preexisting telemetry system 250 kHz carrier frequency).
• A first transceiver90 (e.g., in the EM transmitter34) converts voltage signals to current via the low impedance looking into the termination network of asecond transceiver90 through thetransmission line30 and transmits the current to thesecond transceiver90 over thecommunication line30. The second transceiver90 (e.g., in the EM receiver36) receives the current signal and converts the current signal to a voltage signal to be detected by the subassembly electronics. Thecommunication line30 in this configuration forms part of a current loop at the carrier frequency that includes, e.g., a power supply from thesurface processing unit28, thecommunication line30 and return through the borehole string.
• In one embodiment, eachtransceiver90 includes circuitry for resonant decoupling of the transceiver from telemetry/power signals transmitted over thecommunication line30. For example, resonant decoupling is achieved for the transceivers via a decoupling capacitor92 (“C1” in the transmitter sub and “C2” in the receiver sub) and a transformer94 (“X1” in the transmitter sub and “X2” in the receiver sub). Thecapacitors92 allow for elimination of passing DC voltage acting on thebus30 to the transformer primary winding which could cause excessive power losses and saturate the transformer's core.
• In one embodiment, eachtransformer94, together with an inductor96 (“L1” or “L2”) and an additional capacitor98 (“C3” or “C4”) forms a high quality band pass filter that can be tuned to the transceiver's operating frequency (e.g., 4 MHz). This also allows for effective suppression of low frequency telemetry signals that may be propagated to the transceiver inputs.
• If the input impedance of a current loop receiver “R” were maintained high, a change of the communication line's impedance could de-tune the above mentioned band pass filter. This impedance change could occur if more downhole subs have been connected to the bus and/or their power/telemetry characteristics changed.
• In one embodiment, to mitigate this issue, the current loop receiver module includes a very low impedance front-end amplifier, i.e., operating as a current amplifier, or in transimpedance mode. In this embodiment, the input impedance of the current loop receiver at the transceiver frequency is negligible while remain sufficiently high for telemetry signals. The transceivers' information is delivered from the current loop transmitter to the current loop receiver by current owing from the current loop transmitter output to the current loop receiver input, and the amount of current diverted to connected extra subs will be in reverse proportion to the ratio of their input impedances to the impedance of the current loop receiver. In this way, additional subs or components added to thecommunication line30 do not result in an appreciable change in performance of the current loop.
• The current loop communication system can be configured as a one-way system, where a first component includes only a current loop transmitter and is configured to transmit current signals to a second component that includes only a current loop receiver. In other embodiments, the communication system is configures as a half-duplex or a full-duplex system.
• FIG. 9 shows an exemplary half-duplex arrangement, in which both modules send and receive data at the same frequency, but do so one way at a time. For example, eachtransceiver90 includes circuitry for receiving signals (receiving circuitry100) and transmitting current signals (transmitting circuitry102), which are connected to thecommunication line30 via asolid state switch104. Initially and when in stand-by mode, thereceiver100 is connected to thecommunication line30. Optionally, one of the transceivers operates as a master and another as a slave. When either of thetransceivers90 needs to transmit data, the switch is actuated (via, e.g., acontroller106 following commands from respective tool's electronics) to connect the transmittingcircuitry102 to thecommunication line30.
• FIG. 10 shows an exemplary full-duplex arrangement, in which both modules can exchange data independently and asynchronously. In this example, thereceiver100 in the first component and thetransmitter102 in the second component operate at a first frequency F1, and thereceiver100 in the second component and thetransmitter102 in the first component operate at a first frequency F2.
• The apparatuses and methods described herein provide various advantages over prior art techniques, including providing a method for effective synchronization between downhole components over existing communication/power lines.
• The dual tone synchronization method overcomes disadvantages inherent in prior art methods. For example, for transient EM tools, synchronization of the receiver using the rising edge of voltage signals induced in receiver coils (due to current in the formation induced by the EM transmitter) is possible, however the conductivity of the formation between the transmitter and receiver tends to distort and lengthen the rise time of the rising edge, making synchronization variable, inaccurate and unreliable. Furthermore, this synchronization method can be badly affected by random noise. Algorithms for distinguishing the axis and polarity of dipole reversals by the receiver will likely be complicated and may be unreliable, thus reducing the reliability of a synchronization method using the receiver voltage signals.
• The dual tone synchronization methods overcome these deficiencies and provide an accurate method for time synchronization of transmitters and receivers, e.g., that are placed on separate subassemblies. In addition, the method may be a one-way syncing method that doesn't require two-way communication and handshaking among the affected subassemblies.
• The communication systems and interfaces described herein provide for direct communication between subassemblies by implementing a data channel in a bus or other transmission line that allows for sending high-speed data between subassemblies without interfering with other telemetry and power signals (e.g., between downhole components and surface units) already present on the transmission line. The systems thus are compatible with current tools without requiring engineering modifications to unaffected tools on the string, and allow for transmission of digital communication so that receiver information can be transmitted to the affected subassemblies. In the case of the transient EM tool, the transmit subassembly needs to send the transmit axis and transmit polarity associated with each dipole reversal.
• For example, in the transient EM tool the transmitter and receiver are located on separate subassemblies that have very limited communication capabilities between them. Typically, separate subassemblies on the drill string are powered by a single common wire or other communication line. It is possible for subassemblies to communicate over this bus over a narrow band data channel around 250 kHz. This channel is not suitable for passing sync signals from transmitter to receiver, since the data channel is dedicated to tool control and data acquisition, and cannot be preempted to pass sync signals. The communication systems and interfaces described herein address these deficiencies by providing for direct communication between subassemblies over the communication line via one or more separate data channels that do not interfere with power and/or telemetry channels.
• Generally, some of the teachings herein are reduced to an algorithm that is stored on machine-readable media. The algorithm is implemented by a computer and provides operators with desired output.
• The systems described herein may be incorporated in a computer coupled to various downhole components, subassemblies and/or surface processing units. Exemplary components include, without limitation, at least one processor, storage, memory, input devices, output devices and the like. As these components are known to those skilled in the art, these are not depicted in any detail herein. The computer may be disposed in at least one of a surface processing unit and a downhole component.
• In support of the teachings herein, various analyses and/or analytical components may be used, including digital and/or analog systems. The system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.
• While the invention has been described with reference to exemplary embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims.

Claims (20)

What is claimed is:

1. A method of synchronization between downhole components, the method comprising:

generating a dual tone synchronization signal by a signal generator in a first downhole component disposed in a borehole in an earth formation, the dual tone signal including a first constituent periodic signal having a first frequency f₁and a second constituent periodic signal having a second frequency f₂that is different from the first frequency;

transmitting the synchronization signal to a second downhole component disposed in the borehole;

receiving the synchronization signal by a signal processor in the second downhole component, calculating a phase difference between the first constituent signal and the second constituent signal, and calculating a transmission delay based on the phase difference; and

synchronizing operation of the first and second downhole components based on the delay.

2. The method ofclaim 1, wherein the synchronization signal is transmitted directly to the second downhole component over a transmission line connected between the downhole components and a surface unit.

3. The method ofclaim 2, wherein the transmission line is a single conductor power and telemetry bus.

4. The method ofclaim 2, wherein the synchronization signal is transmitted in a first frequency band that is different than a second frequency band used to transmit communications between the surface unit and the downhole components.

5. The method ofclaim 1, further comprising transmitting a trigger signal from the first downhole component to the second downhole component, the trigger signal indicating a time value measured by the first downhole component.

6. The method ofclaim 5, wherein the time value is a zero crossing point at a selected cycle of the synchronization signal.

7. The method ofclaim 5, wherein the first downhole component includes a transient electromagnetic (TEM) transmitter, the second downhole component includes a TEM receiver, and the trigger signal indicates a time at which the TEM transmitter commences transmitting TEM signals into the earth formation.

8. The method ofclaim 1, wherein the first downhole component and the second downhole component are connected via a current loop communication system.

9. The method ofclaim 8, wherein the first downhole component includes a current loop transmitter configured to convert voltage signals from the first downhole component to current signals and transmit the current signals over a current loop formed by the transmission line.

10. An apparatus for communicating between downhole components, comprising:

an interface coupled to a first downhole component, the interface configured to communicatively couple the first downhole component to a transmission line and transmit signals to a second downhole component over the transmission line, the interface including a current loop transmitter configured to convert voltage signals from the first downhole component to current signals and transmit the current signals on a current loop formed by the transmission line.

11. The apparatus ofclaim 10, further comprising a second interface coupled to the second downhole component, the second interface including a current loop receiver configured to convert current signals received from the first downhole component over the transmission line to voltage signals.

12. The apparatus ofclaim 10, wherein the current loop is formed by the transmission line coupled to a surface power source and a return path formed by a borehole string that includes the downhole components.

13. The apparatus ofclaim 12, wherein the transmission line is a single conductor power and telemetry bus.

14. The apparatus ofclaim 12, wherein the current loop transmitter is configured to transmit the current signals in a first frequency band that is different than a second frequency band used to transmit communications between the surface unit and the downhole components.

15. The apparatus ofclaim 14, wherein the current loop transmitter includes a resonant decoupling device configured to prevent coupling of signals in the second frequency band with the current loop transmitter.

16. The apparatus ofclaim 14, wherein the current loop transmitter includes a band pass filter tuned to frequencies in the first frequency band.

17. The apparatus ofclaim 11, wherein the first interface and the second interface are configured to both transmit and receive current loop signals.

18. The apparatus ofclaim 17, wherein the first interface and the second interface are configured as a half-duplex system to allow for two-way communication.

19. The apparatus ofclaim 17, wherein the first interface and the second interface are configured as a full-duplex system to allow for simultaneous two-way communication.

20. The apparatus ofclaim 10, wherein the first downhole component includes a signal generator configured to generate a dual tone synchronization signal, the dual tone signal including a first constituent periodic signal having a first frequency f₁and a second constituent periodic signal having a second frequency f₂that is different from the first frequency, and the second downhole component includes a processor configured to receive the synchronization signal, calculating a phase difference between the first constituent signal and the second constituent signal, and calculate a transmission delay based on the phase difference.

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